The present invention generally relates to treatment fluids containing chelating agents, and, more particularly, to treatment methods using treatment fluids that contain biodegradable chelating agents.
Treatment fluids can be used in a variety of subterranean treatment operations. Such treatment operations can include, without limitation, drilling operations, stimulation operations, production operations, and sand control treatments. As used herein, the terms “treat,” “treatment” and “treating” refer to any subterranean operation that uses a fluid in conjunction with achieving a desired function and/or for a desired purpose. Use of these terms does not imply any particular action by the treatment fluid. Illustrative treatment operations can include, for example, fracturing operations, gravel packing operations, acidizing treatments, scale dissolution and removal, consolidation treatments, and the like. In alternative embodiments, treatment operations can refer to an operation conducted in a pipe, tubing, or like vessel in conjunction with achieving a desired function and/or for a desired purpose (e.g., scale removal).
In acidizing treatments, for example, subterranean formations comprising acid-soluble components, such as those present in carbonate and sandstone formations, are contacted with a treatment fluid comprising an acid to dissolve the formation matrix. After acidization is completed, the treatment fluid and salts dissolved therein may be recovered by producing them to the surface (e.g., “flowing back” the well), leaving a desirable amount of voids or conductive pathways (e.g., wormholes in carbonates) within the formation. Acidization can enhance the formation's permeability and may increase the rate at which hydrocarbons are subsequently produced from the formation.
Acidizing a siliceous formation (e.g., a sandstone formation or a clay-containing formation) should be distinguished from acidizing a carbonate formation. Carbonate formations can be treated with a variety of acid systems, including mineral acids (e.g., hydrochloric acid), and organic acids (e.g., acetic and formic acids), often with similar success, where the acidity of the treatment fluid alone can be sufficient to solubilize formation cations. The treatment of siliceous formations with these acids, however, may have little or no effect because they do not react appreciably with the silica and silicates that characterize siliceous formations. As used herein, the term “siliceous” refers to the characteristic of having silica and/or silicate, including aluminosilicates. Most sandstone formations are composed of about 40% to about 98% sand quartz particles, i.e., silica (SiO2), bonded together by various amounts of cementing material including carbonate (calcite or CaCO3), aluminosilicates, and silicates.
By far the most common method of treating sandstone and other siliceous formations involves introducing corrosive, very low pH acids comprising hydrofluoric acid into the well bore and allowing the acid to react with the formation matrix. In contrast to other mineral acids, hydrofluoric acid is very reactive with aluminosilicates and silicates (e.g., sandstone, clays and feldspars). Hydrochloric acid may be used in addition to hydrofluoric acid in the treatment fluid to maintain a low pH as hydrofluoric acid is spent during a treatment operation, thereby retaining certain dissolved species in a highly acidic solution. Hydrofluoric acid acidizing is often used to remove damage within the formation. Such treatments are generally not considered “stimulating” in the sense of creating or extending fractures in the formation as in a typical fracturing operation. As a result of a hydrofluoric acid treatment, it is desirable that the skin value in the formation be zero. It is not anticipated that it will be less than zero. Any damage left behind gives a positive skin value, which is not desirable.
Hydrofluoric acid can interact with the formation matrix, base fluids, or formation fluids to create precipitates, particularly in the presence of metal ions such as Al3+, Fe2+, Group 1 metal ions (e.g., Na+ and K+) and/or Group 2 metal ions (e.g., Mg2−, Ca2+, and Ba2+), thereby leading to further damage and a positive skin value. For instance, hydrofluoric acid tends to react very quickly with authigenic clays (e.g., smectite, kaolinite, illite and chlorite), especially at temperatures above 200° F. and below pH 1, as a function of mineral surface area. Because of this quick reaction, the hydrofluoric acid may penetrate only a short distance into the formation before becoming spent. Simultaneously, precipitation of various aluminum and silicon complexes can occur as a result of the reaction of the acid with the siliceous minerals. Damage to the formation can result from this precipitation. At certain temperatures and subterranean conditions, dissolution of a sandstone matrix or like siliceous material may occur so rapidly that uncontrolled precipitation can become an inevitable problem. The precipitation products can plug pore spaces and reduce the porosity and permeability of the formation, thus impairing flow potential.
Because clays are normally a part of the cementitious material that holds the sand grains of siliceous formations together, the dissolution of clay also weakens and de-consolidates the formation matrix in the vicinity of the well bore, thus causing damage to the formation. The damaging effects due to both the de-consolidation of the matrix and the precipitation of complexes can clog the pore spaces of the formation and eliminate or even revert the stimulation effect of an acidizing treatment.
Of particular concern is the formation of calcium fluoride, fluorosilicates, or other insoluble fluoro compounds during hydrofluoric acid acidizing treatments, which can negate the effectiveness of the treatment and cause damage to the formation. This can lead to production delays while damage control operations are conducted. The fluorosilicates can be of particular concern because they are the primary product of the dissolution of a clay and hydrofluoric acid. In addition, fluorosilicates are difficult to remediate. Calcium fluoride can be a later concern in the process, because the fluoride anion needs to be present in its free ion form, and that does not happen until a higher pH is reached. Calcium fluoride can be remediated, in some instances. Remediation techniques include a commercially available treatment system from Halliburton Energy Services, Inc. known as “F-SOL” acid system, which can be used to dissolve calcium fluoride. Another source of concern is the production of fluoroaluminates as a consequence of the reaction of fluorosilicates with clay minerals. Fluoroaluminates are thought to be soluble as long as the pH is below about 2 and the ratio of F/Al is maintained below about 2.5. If precipitated, their dissolution requires strong HCl (>5%).
Avoiding the formation of calcium fluoride, fluorosilicates, or other insoluble fluoro compounds can be a primary design objective in a treatment operation conducted in a subterranean formation or elsewhere. Various means have been used with mixed success. Blends of organic acids and hydrofluoric acid have been used to slow the dissolution kinetics of sandstone formation solids. However, as organic acids have higher pKa values than do mineral acids, precipitation can become problematic as the treatment fluid's pH rises. Pre-flush sequences with acids have been used to remove calcium salts from sandstone formations, before the main acidizing sequence is conducted to remove formation aluminosilicates. Generally, these flushes do not spend completely and typically return, upon flowback, with a persisting low pH. This can result in corrosion of downhole tubular goods (including coiled tubing) and surface equipment. Other multi-stage sandstone acidizing treatment operations have also been developed, particularly to remove calcium ions.
Chelating agents can also be included in treatment fluids to sequester at least a portion of the formation cations that cause unwanted precipitation. However, there are certain operational problems that are encountered with use of many common chelating agents. First, many common chelating agents are not biodegradable or present other toxicity concerns that make their use in a subterranean formation problematic. Further, the salt form of some chelating agents can actually exacerbate precipitation problems in a hydrofluoric acid acidizing treatment rather than lessening the amount of precipitated solid.
Likewise, chelating agents can be used in treating pipelines, tubing, and like vessels by removing metal ion scale from the pipeline or tubing surface. In such treatment operations, significant waste disposal issues can be encountered, since chelating agents that have commonly been used for such purposes are not biodegradable.
In addition to the foregoing, precipitation of formation cations in matrix acidizing operations can also be problematic, even when non-siliceous portions of a subterranean formation are being treated. Although most formation cations can be dissolved with strong acid treatment fluids, dissolution of the formation matrix spends the acid. As the pH of the treatment fluid rises, certain cations can precipitate and damage the formation. In addition, the use of very strong acids in a subterranean formation can lead to downhole corrosion issues, as previously mentioned. These issues can also be encountered when treating pipelines, tubing, and like vessels with an acidic fluid. Sequestration of precipitatable cations in non-siliceous formations or in pipelines, tubing, or like vessels can likewise benefit from a chelating agent in much the same manner as that described above for siliceous formations by keeping the cation in a soluble state over a broad pH range.